System and method for monitoring industrial gas turbine operating parameters and for providing gas turbine power plant control system inputs representative thereof

ABSTRACT

A hybrid digital computer gas turbine power plant control system which may operate in a multiple-control loop arrangement is provided with selected process variable monitoring means. Control system inputs representative of current values of such variables are continuously available to provide positive highly responsive control over a broad range of gas turbine operating conditions. Predictable process sensor errors are effectively eliminated by means of programmed computer operations to thereby insure highly accurate control variable derivation essential to maintaining gas turbine operation at or near design limits.

This is a continuation of application Ser. No. 234,491 filed Mar. 14,1972 now abandoned.

CROSS-REFERENCES TO RELATED APPLICATIONS

U.S. Ser. No. 082,470, filed Oct. 20, 1970 by J. Reuther and T. Giras,entitled IMPROVED SYSTEM AND METHOD FOR OPERATING INDUSTRIAL GAS TURBINEAPPARATUS AND GAS TURBINE ELECTRIC POWER PLANTS PREFERABLY WITH ADIGITAL COMPUTER CONTROL SYSTEM and now continued as Ser. No. 319,114,and assigned to the present assignee.

U.S. Ser. No. 082,469, filed Oct. 20, 1970 by R. Kiscaden and R.Yannone, entitled IMPROVED SYSTEM AND METHOD FOR ACCELERATING ANDSEQUENCING INDUSTRIAL GAS TURBINE APPARATUS AND GAS TURBINE ELECTRICPOWER PLANTS PREFERABLY WITH A DIGITAL COMPUTER CONTROL SYSTEM and nowdivided and continued as U.S. Ser. Nos. 963,635 and 095,174, andassigned to the present assignee.

U.S. Ser. No. 082,467, filed Oct. 20, 1970 by J. Rankin and T. Reed,entitled IMPROVED CONTROL COMPUTER PROGRAMMING METHOD AND IMPROVEDSYSTEM AND METHOD FOR OPERATING IND . . . , and assigned to the presentassignee.

U.S. Ser. No. 189,633, filed Oct. 15, 1971 by J. Reuther and T. Reed,entitled "Improved Digital Computer Control System And Method ForMonitoring And Controlling Operation Of Industrial Gas Turbine ApparatusEmploying Expanded Parametric Control Algorithm", and assigned to thepresent assignee and now issued as U.S. Pat. No. 3,866,109.

U.S. Pat. No. 3,924,140, issued Dec. 2, 1975 by R. Yannone, entitled"Improved System And Method For Monitoring And Controlling IndustrialGas Turbine Power Plants Including A Facility For Dynamic Calibration OfControl Instrumentation", and assigned to the present assignee.

BACKGROUND OF THE INVENTION

The present invention relates to gas or combustion turbine apparatus,gas turbine electric power plants and control systems and operatingmethods therefor.

Industrial gas turbines may have varied cycle, structural andaerodynamic designs for a wide variety of uses. For example, gasturbines may employ the simple, regenerative, steam injection orcombined cycle in driving an electric generator to produce electricpower. Further, in these varied uses the gas turbine may have one ormore shafts and many other rotor, casing, support, and combustion systemstructural features which can vary relatively widely among differentlydesigned units. They may be aviation jet engines adapted for industrialservice as described, for example, in an ASME paper entitled "The Prattand Whitney Aircraft Jet Powered 121MW Electrical Peaking Unit"presented at the New York Meeting in November-December, 1964.

Gas turbine electric power plants are usable in base load, mid-rangeload and peak load power system applications. Combined cycle plants arenormally usable for the base or mid-range applications, while the powerplant which employs a gas turbine only as a generator drive typically ishighly useful for peak load generation because of its relatively lowinvestment cost. Although the heat rate for gas turbines is relativelyhigh in relation to steam turbines, the investment savings for peak loadapplication typically offsets the higher fuel cost factor. Anothereconomic advantage for gas turbines is that power generation capacitycan be added in relatively small blocks such as 25MW or 50MW as neededfor expected system growth, thereby avoiding excessive capitalexpenditure and excessive system reserve requirements. Furtherbackground on peaking generation can be obtained in articles such as"Peaking Generation", a Special Report of Electric Light and Power datedNovember, 1966.

Startup availability and low forced outage rates are particularlyimportant for peak load power plant applications of gas turbines. Thus,reliable gas turbine startup and standby operations are particularlyimportant for power system security and reliability.

In the operation of gas turbine apparatus and electric power plants,various kinds of controls have been employed. Relay-pneumatic typesystems form a large part of the prior art. More recently, electroniccontrols of the analog type have been employed as perhaps represented byU.S. Pat. No. 3,520,133 entitled "Gas Turbine Control System" and issuedon July 14, 1970 to A. Loft, or by the control referred to in an articleentitled "Speedtronic Control, Protection and Sequential System", anddesignated as GER-2461 in the General Electric Gas Turbine ReferenceLibrary. A wide variety of controls have been employed for aviation jetengines including electronic and computer controls as described, forexample, in a March, 1968 ASME Paper presented by J. E. Bayati and R. M.Frazzini, and entitled "Digatec" (Digital Gas Turbine Engine Control),an April, 1967 paper in the Journal of the Royal Aeronautical Societyauthored by E. S. Eccles and entitled "The Use Of A Digital Computer ForOn-Line Control Of A Jet Engine", or a July, 1965 paper entitled "TheElectronic Control Of Gas Turbine Engines" by A. Sadler, S. Tweedy andP. J. Colburn in the July, 1965 Journal of the Royal AeronauticalSociety. However, the operational and control environment for jet engineoperations differs considerably from that for industrial jet turbines.In referencing prior art publications or patents as background herein,no representation is made that the cited subject matter is the bestprior art.

In connection with prior art gas turbine electric power plant operatingand control systems and operating methods therefor, reference is made tocopending related application Ser. No. 082,470 which, in conjunctionwith other enumerated related patent applications, comprises adescription of an improved gas turbine plant operating and controlsystem. The present disclosure represents a further advancement over theprior art discussion herein contained and should be considered asexclusive of the referenced application.

Generally, the operation of industrial gas turbine apparatus and gasturbine power plants has been limited in flexibility, response speed,accuracy and reliability. Further limits have existed in the efficiencyor economy with which single or multiple units are placed underoperational control and management. Control loop arrangements andcontrol system embodiments of such arrangements for industrial gasturbines have been less effective in operations control than isdesirable. Limits have also existed on how close industrial gas turbinescan operate to the turbine design limits over various speed and/or loadranges.

More particularly, in gas turbine control, substantially continuousmonitoring of turbine parameters accurately reflecting operatingconditions at the various operation cycle positions is essential.Optimum operation over a wide range of operating conditions can beassured only by such monitoring and by reliable, accurate control loopresponse to variations in one or more of such parameters. Further,certain critical parameters must be continuously sensed in order toprevent damage to combustor elements, hot parts, rotor blades, etc., inthe event of over-temperature or overload conditions.

Process sensors of various types have been employed to furnish controlsystem inputs. For example, temperature and pressure sensors have beenlocated at various turbine cycle positions and in varyingconfigurations.

Accurate reliable temperature and pressure indications have beenincreasingly recognized as essential to maintaining the integrity of asystem having one or more control loops wherein it is sought to controlturbine speed or load in response to a temperature and/or pressurederived fuel demand signal. During turbine startup, accurate combustorshell pressure indications have been found to be of particularimportance. Again, under load accurate pressure readings may becomeessential to efficient operation.

During those modes of operation characterized principally by temperatureconrol, the accuracy and reliability of such indications determine thedegree to which optimum operating conditions may be attained. Adescription of an improved control system employing optimally arrangedturbine system thermocouples, suitable for use in the gas turbineelectric power plant of the present invention, may be found in copendingapplication Ser. No. 155,905.

As gas turbine automatic control system developed, it becameincreasingly essential to obtain reliable temperature and pressureindications for use as control parameters in developing a fuel controlinput in the various control modes of operation. It became necessary tocontinuously review such measurements, not only for the purpose ofassuring reliable, safe operation, but further to insure theavailability of control variables which would enable efficient operationof the gas turbine near design limits to thereby enhance overallefficiency of the automatic control system. Known prior art controlsystems have lacked a facility for deriving consistently accuratecontrol variables representative of critical parameters such as turbineinlet temperature, combustor shell pressure and turbine exhausttemperatures.

Although known prior art gas turbine control systems have providedmultiple control loops in part responsive to temperature and pressureinputs, difficulties in obtaining continuous control over all operatingmodes has persisted, in a large part, as a result of an inability toobtain precise temperature and pressure inputs over a broad range ofoperating conditions. Over some portions of gas turbine operation, forexample, temperature measuring errors and poor response of temperaturemeasuring instrumentation have produced thermal lag so that response tostep impulse inputs has been inadequate to achieving the highlyresponsive and flexible control necessary in most applications of gasturbine apparatus. Clearly, an alternative to temperature control hasbeen indicated, in order to reduce undesirable thermal transients.Controlling as a function of combustor shell pressure over this intervalof gas turbine operation presents an immediate alternative. However,problems have persisted in such control as hereinbefore indicated.

Problems encountered in controlling fuel system operation as a functionof compressor shell pressure during gas turbine start-up and duringsubsequent modes of operation have indicated reliance on other operatingparameters to achieve positive control during this time interval.Characteristically, such systems have not provided adequate control overa broad range of ambient temperatures. Variations in such ambienttemperatures are known to cause significant variations in internaltemperatures which may shorten the life of turbine components, such asblading and the like. A characteristic prior art control system callsfor an initial shot of fuel upon detection of flame at light-off, with asubsequent cut-back from the initial impulse level to reduce thermalshock to hot path parts. At the end of the warm-up period, positivecontrol is resumed as a function of temperature or acceleration.Clearly, such control is inadequate to preventing the effects of thermaltransient or thermal shock to the critical turbine components.

Various methods and apparatus exist for obtaining, calibrating anddisplaying instantaneous values of critical turbine operatingparameters. Characteristically, however, calibration of variousinstrumentation employed in obtaining control system inputs has beenlimited to a one-time setting prior to turbine start-up of instrumentsto indicate extreme values on a known scale, e.g., alignment of theparticular dial at the zero and maximum setting, for example, acombustor shell pressure transducer provides readings from zero to 160psig. Previously, calibration procedures had suggested an alignment of adial at zero and 160 with an implicit assumption that increments betweenthe two extreme values will be linearly a function of combustor shellpressure. Nowhere is there suggested in known prior art control systemsa facility for dynamically correcting for transducer error. Prior artcontrollers have had no facility for remembering the zero point as readwhen the unit was shut down so that re-zeroing might be accomplishedduring gas turbine operation. For the foregoing and for other reasons,difficulties have existed in obtaining the reliable, accurate combustorshell pressure indications necessary to the provision of responsivesurge control during gas turbine start-up and during the other operatingmodes of industrial gas turbine apparatus. Dynamic calibrationtechniques have been lacking so that calibration before start-up hasbeen relied upon exclusively. Specifically a variety of fieldexperiences have demonstrated particular problems in calibratingcombustor shell pressure transducers so that they repeat exactly to azero reading after shut-down. The readings in the vicinity of zeropounds are very critical during the initial light-off period since, asdiscussed previously, combustor shell pressure is desirably consideredin preventing compressor surge during this period. Variations in zerosetting cause greatly varying light-off temperature control as verifiedby recorder traces taken in the field. Certain, otherwise adequatecontrol algorithms and systems dictate inhibition of start-up if thepressure transducer is uncalibrated by more than one half pound at thezero point. Thus the problem of transducers repeating to zero pounds hasaffected availability and reliability.

SUMMARY OF THE INVENTION

One or more industrial gas turbines or gas turbine power plants areoperated by a control system which preferably is a programmed digitalcomputer in a hydrid control system arrangement preferably to controlfuel flow and thereby provide load and loading rate control over theturbine and generator or other load unit and further provide speed,surge and temperature limit control with nonlinear control loopcharacterization. Control loop integrity is enhanced by dynamic testingof control system input parameters and correction of processinstrumentation calibration errors.

More specifically, as regards control system actions in response todeviation of process sensor inputs from predetermined calibrated limits,programmed computer operations are performed on a periodic basis tocorrect predictable excursions so that error free control variables areavailable for further processing. Combustor shell pressure readings arethus corrected to provide highly accurate compressor surge limitingessential to accurate fuel scheduling during critical light-off period.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a top plan view of a gas turbine power plant arranged tooperate in accordance with the principles of the invention;

FIG. 2 shows a schematic view of a rotating rectifier exciter and agenerator employed in the gas turbine power plant of FIG. 1;

FIG. 3 shows a front elevational view of an industrial gas turbineemployed in the power plant to drive the generator and it is shown withsome portions thereof broken away;

FIGS. 4-6 show a fuel nozzle and parts thereof employed in the gasturbine of FIG. 3;

FIGS. 7 and 8 respectively show schematic diagrams of gas and liquidfuel supply systems employed with the gas turbine of FIG. 3;

FIG. 9 shows a block diagram of a digital computer control systememployed to operate the gas turbine power plant of FIG. 1;

FIG. 10 shows a block diagram of a control loop which may be employed inoperating the computer control system of FIG. 9 and the power plant ofFIG. 1;

FIGS. 11A-B show schematic diagrams of control loops which may beemployed in operating the computer control system of FIG. 9 and thepower plant of FIG. 1;

FIGS. 12, 13 and 14 illustrate various curve data employed in thecontrol system computer in the operation of the gas turbine power plant;

FIG. 15 shows a sequence chart for startup and shutdown of the gasturbine power plant;

FIGS. 16A and 16B show a schematic diagram of analog circuitryassociated with the computer in the control system to provide controlover gas turbine fuel supply system operations and certain other plantfunctions;

FIG. 17 shows a general block diagram of the organization of a programsystem employed in the control system computer;

FIG. 18 illustrates a flowchart for a sequencing program associatedprincipally with startup operations for the gas turbine;

FIG. 19 shows a data flow diagram which illustrates the manner in whichthe sequencing program is executed to provide multiple power plantoperations with a single control computer;

FIGS. 20A-B shows a logic diagram representative of the sequencing logicperformed by the sequencing program;

FIG. 21 shows a block diagram of a control loop arrangement implementedin the preferred embodiment;

FIG. 22 shows a data flow diagram associated with control programoperations during controlled operation of multiple gas turbine powerplants with a single control computer;

FIG. 23 illustrates a flowchart which represents control programoperations in the preferred embodiment;

FIG. 24 shows a more detailed flowchart for a speed reference generationfunction included in the program of FIG. 23;

FIG. 25 shows a more detailed flowchart for a gas turbine blade path andexhaust temperature limit function employed in the program of FIG. 29;

FIGS. 26A-D show respective control configurations of software elementsassociated respectively with Mode 0 through Mode 4 operations;

FIGS. 27A-B respectively show software control configurations for theblade path temperature and exhaust temperature limit functions;

FIG. 28 shows a flow diagram for control program operations whichprovide load control and load limit functions for the gas turbine powerplant;

FIG. 29 illustrates a flowchart for a load rate limit function employedin the load control and limit operations illustrated in FIG. 28;

FIG. 30 shows a flowchart for a rate function employed in temperaturelimit operations; and

FIGS. 31A-B show flow diagrams for the program steps employed inaccomplishing the dynamic calibration and error correction of thepresent invention in operating Modes 0 and 1, respectively.

DESCRIPTION OF THE PREFERRED EMBODIMENT A. POWER PLANT 1. GeneralStructure

More particularly, there is shown in FIG. 1 a gas turbine electric powerplant 100 which includes an AC generator 102 driven by a combustion orgas turbine 104 through a reduction gear unit 106. In this applicationof the invention, the gas turbine 104 is the W-251G simple cycle typemanufactured by Westinghouse Electric Corporation. In other power plantgenerator applications, other industrial drive applications, andcombined steam and gas cycle applications of various aspects of theinvention, industrial gas turbines having larger or smaller powerratings, different cycle designs, different number of shafts orotherwise different from W-251G can be employed.

The plant 100 may be housed in an enclosure (not shown) and then placedon a foundation approximately 106 to 115 feet long dependent upon thenumber of optional additional plant units to be accommodated thereon. Upto three additional units may be provided. Exhaust silencers 108 and 110coupled respectively to inlet and exhaust duct works 112 and 114significantly reduce noise characteristicly associated with turbinepower plants.

Digital computer and other control systems circuitry in a cabinet 118provides for operation of the power plant 10 when a single plant unit isselected by the user. Associated therewith is an operator's panel 120,an automatic send/receive printer 122 and a protective relay panel 124for sensing abnormal electric power system conditions. The number ofbasic master and slave units 118 through 124 provided may vary accordingas the number of plants being monitored and controlled.

Startup or cranking power for the plant 100 is provided by a startingengine 126 such as a diesel engine. Starting engine 126 is mounted on anauxiliary bedplate and coupled to the drive shaft of the gas turbine 104through a starting gear unit 128. A DC motor 154 operates through aturning gear 156 which is also coupled to the gas turbine shaft startinggear 128 to drive the gas turbine at turning gear speed.

A motor control center 130 is also mounted on the auxiliary bedplate andit includes motor starters and other devices to provide for operatingthe various auxiliary equipment items associated with the plant 100.

A plant battery 132 is disposed adjacent to one end of the auxiliarybedplate or skid. The battery provides power for emergency lighting,auxiliary motor loads, and DC computer and other control power for aperiod following shutdown of the plant 100 due to a loss of AC power.Also included on the auxiliary skid is pressure switch and gauge cabinet152 which contains the pressure switches, gauges, regulators and othermiscellaneous elements needed for gas turbine operation.

A switchgear pad 142 is included in the plant 100 for 15 KV switchgearincluding the generator breaker as indicated by the reference characters144, 146 and 148. Excitation switchgear 150 associated with thegenerator excitation system is also included on the switchgear pad 142.

2. Generator and Exciter

The generator 102 and its brushless exciter 103 are schematicallyillustrated in greater detail in FIG. 2. Structural details as well asdetails of operation are considered more fully in the aforementionedcopending application Ser. No. 882,470 Section A2, pages 21 to 24.

Briefly, a permanent magnet field member 164 is rotated to inducevoltage in a pilot exciter armature 166 which is coupled to a stationaryAC exciter field 168 through a voltage regulator 170. Voltage is therebyinduced in an AC exciter armature 172 formed on the exciter rotatingelement and it is applied across diodes mounted with fuses on a diodewheel 174 to energize a rotating field element 176 of the generator 102.Generator voltage is induced in a stationary armature winding 178 whichsupplies current to the power system through a generator breaker whenthe plant 100 is synchronized and on the line. A transformer 180supplies a feedback signal for the regulator 170 to control theexcitation level of the exciter field 168.

Various monitoring devices to be hereinafter more fully described areprovided which generate input data for the plant control system.Included are vibration transducers 162 and 164 resistant temperaturedetectors embedded in the stator winding and thermocouples installed tomeasure air inlet discharge temperature and bearing oil draintemperatures. In this manner alarm conditions are provided to thecontrol system. Additional control functions are provided to adjust baseadjust rheostats 171 and 177 to provide fine generator voltage control.

3. Gas Turbine a. Compressor

The gas turbine 104 in this case is the single shaft simple cycle typehaving a standard ambient pressure ratio of 9.0 to 1 and a rated speedof 4894 rpm and it is illustrated in greater detail in FIG. 3. Filteredinlet air enters a multistage axial flow compressor 181 through aflanged inlet manifold 183 from the inlet ductwork 112. An inlet guidevane assembly 182 includes vanes supported across the compressor inletto provide for surge prevention particularly during startup. The angleat which all of the guide vanes are disposed in relation to the gasstream is uniform and controlled by a pneumatically operated positioningring coupled to the vanes in the inlet guide vane assembly 182.

The compressor 181 is provided with a casing 184 which is split intobase and cover parts along a horizontal plane. The turbine casingstructure including the compressor casing 184 provides support for aturbine rotating element including a compressor rotor 186 throughbearings 188 and 189. Vibration transducers (FIG. 9) are provided forthe gas turbine bearings 188 and 189.

The compressor casing 184 also supports stationary blades 190 insuccessive stationary blade rows along the air flow path. Further, thecasing 184 operates as a pressure vessel to contain the air flow as itundergoes compression. Bleed flow is obtained under valve control fromintermediate compressor stages to prevent surge during startup.

The compressor inlet air flows annularly through a total of eighteenstages in the compressor 181. Blade 192 mounted on the rotor 186 bymeans of wheels 194 are appropriately designed from an aerodynamic andstructural standpoint for the intended service. A suitable material suchas 12% chrome steel is employed for the rotor blades 192. Both thecompressor inlet and outlet air temperatures are measured by suitablysupported thermocouples (FIG. 9).

b. Combustion System

Pressurized compressor outlet air is directed into a combustion system196 comprising a total of eight combustor baskets 198 conically mountedwithin a section 200 of the casing 184 about the longitudinal axis ofthe gas turbine 104. In accordance with one aspect of the principles ofthe present invention control system inputs representative of combustorshell pressure are obtained by a suitable strategically located, sensor(FIG. 9) coupled to the compressor combustor flow paths located in thepressure switch and gauge cabinet 152. The pressure detector/transducercan for example, be one such as that described in Product Bulletin(PB)-107-109 published by Hagan Computer and Instrumentation Division ofWestinghouse Electric Corporation and designated "Transducer HighPressure Model-109".

As schematically illustrated in FIG. 4, the combustor baskets 198 arecross-connected by cross-flame tubes 202 for ignition purposes. Acomputer sequenced ignition system 204 includes igniters 206 and 208associated with respective groups of four combustor baskets 198. In eachbasket group, the combustor baskets 198 are series cross-connected andthe two groups are cross-connected at one end only as indicated by thereference character 210.

Generally, the ignition system 204 includes an ignition transformer andwiring to respective spark plugs which form a part of the igniters 206and 208. The spark plugs are mounted on retractable pistons within theigniters 206 and 208 so that the plugs can be withdrawn from thecombustion zone after ignition has been executed.

A pair of ultraviolet flame detectors 212 are associated with each ofthe end combustor baskets in the respective basket groups in order toverify ignition and continued presence of combustion in the eightcombustor baskets 198. The flame detectors 212 can for example be Edisonflame detectors Model 424-10433.

In FIG. 5, there is shown a front plan view of a dual fuel nozzlemounted at the compressor end of each combustor basket 198. An oilnozzle 218 is located at the center of the dual nozzle 216 and anatomizing air nozzle 220 is located circumferentially about the oilnozzle 218. An outer gas nozzle is disposed about the atomizing airnozzle 220 to complete the assembly of the fuel nozzle 216.

As indicated in the broken away side view in FIG. 6, fuel oil or otherliquid fuel enters the oil nozzle 218 through a pipe 224 while atomizingair for the fuel oil enters a manifold pipe arrangement 226 throughentry pipe 228 for flow through the atomizing air nozzle 220. Gaseousfuel is emitted through the nozzle 222 after flow through entry pipe 230and a manifold pipe arrangement 232.

c. Fuel

Generally, either liquid or gaseous or both liquid and gaseous fuel flowcan be used in the turbine combustion process. Various gaseous fuels canbe burned including gases ranging from blast furnace gas having low BTUcontent to gases with high BTU content such as natural gas, butane orpropane.

With respect to liquid fuels, the fuel viscosity must be less than 110SSU at the nozzle to assure proper atomization. Most distillates meetthis requirement.

A portion of the compressor outlet air flow combines with the fuel ineach combustor basket 198 to produce combustion after ignition and thebalance of the compressor outlet air flow combines with the combustionproducts for flow through the combustor basket 198 into a multistagereaction type turbine 234 (FIG. 3). The combustor casing section 200 iscoupled to a turbine casing 236 through a vertical casing joint 238. Nohigh pressure air or oil seal is required between the compressor 181 andthe turbine 234.

d. Turbine Element

The turbine 234 is provided with three reaction stages through which themultiple stream combustion system outlet gas flow is directed in anannular flow pattern to transform the kinetic energy of the heated,pressurized gas into turbine rotation, i.e. to drive the compressor 181and the generator 102. The turbine rotor is formed by a stub shaft 240and three disc blade assemblies 240, 242 and 244 mounted on the stubshaft by through bolts. Thermocouples (FIG. 9) are supported within thedisc cavities to provide cavity temperature signals for the controlsystem.

High temperature alloy rotor blades 246 are mounted on the discs informing the disc assemblies 240, 242 and 244. Individual blade roots arecooled by air extracted from the outlet of the compressor 181 and passedthrough a coolant system in the manner previously indicated. The bladeroots thus serve as a heat sink for the rotating blades 246. Cooling airalso flows over each of the turbine discs to provide a relativelyconstant low metal temperature over the unit operating load range.

In addition to acting as a pressure containment vessel for the turbine234, the turbine casing 236 supports stationary blades 248 which formthree stationary blade rows interspersed with the rotor blade rows. Gasflow is discharged from the turbine 234 substantially at atmosphericpressure through a flanged exhaust manifold 250 to the outlet ductwork114.

The generator and gas turbine vibration transducers (FIG. 9) can beconventional velocity transducers or pickups which transmit basicvibration signals to a vibration monitor for input to the controlsystem. A pair of conventional speed detectors (FIGS. 9 and 15A) areassociated with a notched magnetic wheel (FIG. 15A) supported atappropriate turbine-generator shaft locations. Signals generated by thespeed detectors are employed in the control system in determining powerplant operation.

Thermocouples (FIG. 9) are associated with the gas turbine bearing oildrains. Furthermore, thermocouples (FIG. 9) for the blade path aresupported about the inner periphery of the exhaust manifold 250 toprovide a fast response indication of blade temperature for controlsystem usage particularly during plant startup periods. Exhausttemperature detectors (FIG. 9) are disposed in the exhaust ductwork 114primarily for the purpose of determining average exhaust temperature forcontrol system usage during load operations of the power plant 100.Suitable high response shielded thermocouple for the gas turbine 104 arethose which use compacted alumina insulation with a thin-wall high alloyswaged sheath or well supported by a separate heavy wall guide.

e. Fuel System

A fuel system 251 is provided for delivering gaseous fuel to the gasnozzles 222 under controlled fuel valve operation as schematicallyillustrated in FIG. 7. Gas is transmitted to a diaphragm operatedpressure regulating valve 254 from the plant gas source. A pressureswitch 255 provides for transfer to oil fuel at a low gas pressurelimit. Pressure switches 257 and 259 provide high and low pressure limitcontrol action on the downstream side of the valve 254. It is noted atthis point in the description that IEEE switch-gear device numbers aregenerally used herein where appropriate as incorporated in AmericanStandard C37.2-1956.

A starting valve 256 determines gas fuel flow to the nozzles 222 atturbine speeds up to approximately 10% rated flow, and for this purposeit is pneumatically positioned by an electropneumatic converter 261 inresponse to an electric control signal. At gas flow from 10% to 100%rated, a throttle valve 258 determines gas fuel flow to the nozzles 222under the pneumatic positioning control of an electropneumatic converter263 and a pneumatic pressure booster relay 265. The converter 263 alsoresponds to an electric control signal as subsequently more fullyconsidered.

A pneumatically operated trip valve 260 stops gas fuel flow undermechanical actuation if turbine overspeed reaches a predetermined levelsuch as 110% rated speed. A pneumatically operated vent valve 262 allowstrapped gas to be vented to the atmosphere if the trip valve 260 and anon/off pneumatically operated isolation valve 264 are both closed. Theisolation valve fuel control action is initiated by an electric controlsignal applied through the pressure switch and gauge cabinet 152 (FIG. 1and FIG. 9). A pressure switch 267 indicates fuel pressure at the inletto the nozzle 222.

As schematically shown in FIG. 8, a liquid fuel supply system 26provides for liquid fuel flow to the eight nozzles 218 from the plantsource through piping and various pneumatically operated valves by meansof the pumping action of a turbine shaft driven main fuel pump 268. Pumpdischarge pressure is sensed for control system use by a detector 269. Abypass valve 271 is pneumatically operated by an electropneumaticconverter 270 and a booster relay 272 to determine liquid fuel bypassflow to a return line and thereby regulate liquid fuel dischargepressure. An electric control signal provides for pump dischargepressure control, and in particular it provides for ramp pump dischargepressure control during turbine startup. A throttle valve 272 is held ata minimum position during the ramp pressure control action on thedischarge pressure regulator valve 270. A pressure switch 269 providesfor DC backup pump operation on low pressure, and a pressure switch 271indicates whether the pump 268 has pressurized intake flow.

After pressure ramping, the pneumatically operated throttle valve 272 ispositioned to control liquid fuel flow to the nozzle 218 as determinedby an electropneumatic converter 274 and a booster relay 276. Anelectric control signal determines the converter position control actionfor the throttle valve 272. The bypass valve 270 continues to operate tohold fuel discharge pressure constant.

As in the gas fuel system 251, a mechanically actuated and pneumaticallyoperated overspeed trip valve 278 stops liquid fuel flow in the event ofturbine overspeed. A suitable filter 280 is included in the liquid fuelflow path, and, in the gas fuel system 251, an electrically actuated andpneumatically operated isolation valve provides on/off control of liquidfuel to a liquid manifold 283.

Eight positive displacement pumps 284 are respectively disposed in theindividual liquid fuel flow paths to the nozzles 218. The pumps 284 aremounted on a single shaft and they are driven by the oil flow from themanifold 283 to produce substantially equal nozzle fuel flows. Checkvalves 286 prevent back flow from the nozzles 218 and a pressure switch288 indicates fuel pressure at the oil nozzle 218. A manifold drainvalve 290 is pneumatically operated under electric signal control duringturbine shutdown to drain any liquid fuel remaining in the manifold 283.

4. Plant Performance Characteristics

Details concerning plant performance characteristics are contained inthe aforementioned related application Ser. No. 082,470, Section A4,pages 32 to 36.

B. Power Plant Operation And Control 1. General

The preferred embodiment of the integrated turbine generator controlsystem 300 (FIG. 9) employs analog digital computer circuitry to providesequenced start-stop plant operation, monitoring and alarm functions forplant protection and accurately, reliably and efficiently performingspeed/load control during plant startup, running operation and shutdown.The plant control system 300 is characterized with centralized systemspackaging having a single operator's panel and embracing elementsdisposed in the control cabinet 118, the pressure switch and gaugecabinet 152 and other elements included in the electric power plant 100of FIG. 1. If multiple plants like the power plant 100 are to beoperated, plural control cabinets may be required to provide theadditional circuitry needed for the additional plant operations.

The control philosophy embodied in the control system 300 providesflexible operator/control system interfaces. Under automatic control,the power plant 100 can be operated under local operator control or itcan be attended and operated by direct wired remote or supervisorycontrol.

2. Control Loop Arrangement--Characterization

In FIG. 10 a control loop arrangement 302 represented by SAMA standardfunction symbols characterizes the preferred general control loopingembodied in the preferred control system 300 and applicable in a widevariety of other applications of the invention. Reference is made to theaforementioned copending application Ser. No. 082,470, Section B2, pages39 to 51, wherein there is contained a more detailed discussion of thecontrol loop 302.

Briefly, the control loop arrangement 302 comprises an arrangement ofblocks in the preferred configuration of process control loops for usein operating the gas turbine power plant 100 or other industrial gasturbine apparatus. No delineation is made in FIG. 10 between hardwareand software elements since many aspects of the control philosophy canbe implemented in hard or soft form. However, it is noteworthy thatvarious advantages are gained by hybrid software/hardware implementationof the control arrangement 302 and preferably by implementation in thehybrid form represented by the control system 300.

Generally, in the various control mode sequences to be hereinafter morefully discussed, the plant 100 is started from rest under control ofloop 302, accelerated under accurate and efficient control tosynchronous speed, preferably in a normal fixed time period,synchronized manually or automatically with the power system, and loadedunder preferred ramp control to a preselectable constant or temperaturelimit controlled load level, thereby providing better overall powerplant management.

In the combination of plural control loop functions in the arrangement302, a low fuel demand selector block 316 is preferably employed tolimit the speed reference fuel demand representation if any of threelimit representations are exceeded by it during startup. These limitrepresentations are generated respectively by a surge control 318, ablade path temperature control 320, and an exhaust temperature control322. In this application, a load control block 324 becomes operativeafter synchronization with the limit blocks 318, 320 and 322. Thus, theoperation of the plural control loop 302 as a function of the variouslimit representations varies during the various control modes ofoperation.

At the output of the low fuel demand selector 316 the fuel demandrepresentation is applied to a dual fuel control 317 where the fueldemand signal is processed to produce a gas fuel demand signal forapplication to the gas starting and throttle valves or a liquid fueldemand signal for application to the oil throttle and pressure bypassvalve or as a combination of gas and liquid fuel demand signals forapplication to the gas and oil valves together.

In order to start the plant 100, the control system 300, operating incontrol Mode O, requires certain status information generated by thevarious process sensors. Once it is logically determined that theoverall plant status is satisfactory, the plant startup is initiated.Plant devices are started in parallel when possible to increase plantavailability for power generation purposes.

As control is transferred through the various control modes afeedforward characterization is preferably used to determinerepresentation of fuel demand needed to satisfy speed requirements.Measured process variables including turbine speed, the controlled loadvariable or the plant megawatts, combustor shell pressure and turbineexhaust temperature are employed to limit, calibrate or control the fueldemand so that apparatus design limits are not exceeded. Thecharacterization of the feedforward speed fuel demand, a surge limitfuel demand and a temperature limit fuel demand are preferablynon-linear in accordance with the non-linear characteristics of the gasturbine to achieve more accurate, more efficient, more available andmore reliable gas turbine apparatus operation. The control arrangement302 has capability for maintaining cycle temperature, gas turbineapparatus speed, acceleration rate during startup, loading rate andcompressor surge margin.

The fuel demand in the control arrangement 302 provides position controlfor turbine gas or liquid fuel valves. Further, the control arrangement302 can provide for simultaneous burning of gas and liquid fuel and itcan provide for automatic bumpless transfer from one fuel to the otherwhen required.

As will be appreciated from the foregoing discussion control arrangement302 is implemented such that different process variables are givengreater weight in determining the control function to be performed ascontrol progresses sequentially through the various modes of operation.Attention is directed to the critical startup period from light off toattainment of synchronous speed. It is within this time frame ofreference that surge control is of particular importance in minimizingrisk of exceeding gas turbine design temperature limits. The surgecontrol 318 includes a characterization block 325 which responds tosensed combustor shell pressure and compressor inlet temperature togenerate the surge limit representation for compressor surge preventionas illustrated in FIG. 11B.

Referring to FIG. 12, the curve 326 limits startup fuel demand for anambient temperature of 120° F. and the curve 328 limits startup fueldemand for an ambient temperature demand of -40° F. (Common curveportions 330 are operative to provide a substantially linear surge limitduring subsequent load operations.

As shown in FIG. 11C, the blade path temperature control 320 includes ablock 332 which responds to combustor shell pressure in accordance witha preferably nonlinear temperature reference characteristic 334 fornormal startup and a second preferably nonlinear temperature referencecharacteristic 336 for emergency startup as illustrated in FIG. 13. Theexhaust temperature control 322 includes a block 338 which responds tocombustor shell pressure in accordance with temperature referencecharacteristic 340 for base load operation, 342 for peak load and 344for system reserve load operation as shown in FIG. 14. Again eachcharacteristic is preferably nonlinear. The startup curves 334 and 336correspond respectively to 1200° F. and 1500° F. turbine inlettemperature while the load curve correspond to respectively highervalues of turbine inlet temperature operations.

The control loop features described above provide the most accurate andreliable turbine control during startup operations, i.e., over theoperation time interval indicated control as a function of combustorshell pressure is found to be the most reliable. Difficulties inmetering fuel and firing at low speeds are overcome. Low air flow,further complicated by temperature measuring errors and slow response oftemperature sensors creates a control environment in which parametricfuel scheduling, required to reduce thermal transients, is highlydesirable. Thermal shock, contributing to considerable wear and earlydeterioration of turbine components, is significantly reduced.

As will be hereinafter more fully described, the control system isimplemented in accordance with the principles of the present inventionprovides for positive highly responsive control over all modes ofturbine operation. The low fuel demand select features in the describedsystem allow precise control consistent with satisfying the mostappropriate constraint at any given time. Instruments known to providethe best indications of operating conditions at any given time arecalibrated dynamically yielding error free control variables,significantly enhancing accurate response.

Control over early time intervals as a function of combustor shellpressure eliminates problem encountered in systems wherein approximatefuel requirements dictate initial scheduling at a level corresponding toan impulse step control input. As seen by a reference to FIGS. 12, 13and 14, temperature and pressure is simultaneously considered inderiving a most favorable fuel schedule for efficient operation.

3. Control System

The control system 300 is shown in block diagram detail in FIG. 9. Itincludes a general purpose digital computer system comprising a centralprocessor 304 and associated input/output interfacing equipment such asthat sold by Westinghouse Electric Corporation under the trade nameProdac 50 (P50). Generally, the P50 computer system employs a 16,000word core memory, with a word length of 14 bits and a 4.5 microsecondcycle time.

More specifically, the interfacing equipment for the computer 304includes a contact closure input system 306 and a conventional analoginput system 308. Sixtyfour input/output channels each having 14 bitparallel paths into and out of the main frame are provided. Each of theemployed interrupt inputs causes a separate and unique response withinthe computer main frame without need for additional input operationsthereby allowing the processing of interrupt input signals with verylittle main frame duty cycle.

Process inputs are provided by the contact closure input system 306 andthe analog input system 308. The contact closure input (CCI) system iscoupled to the operator console panel 120 and remote operator's panel322. Characteristic CCI's are those related to the starting enginecontacts. Also, a facility exists for customer selection of devices tobe coupled to the CCI system.

Characteristic inputs to the analog input system 308 are the outputsfrom the various plant process sensors and detectors, namely, turbine104 sensors such as blade path and exhaust manifold thermocouples.Additional inputs are those from a combustor shell pressure sensor andthe main and backup speed sensors. The speed sensor outputs are coupledto the analog input system 308 through an analog speed control 324 andan auxiliary speed limiter 326, respectively.

The computer supplies essential outputs of various description fordisplay at the operator's console 120 or the like. They are also appliedas analog inputs as indicated by reference character 330. The contactclosure output system 316 transfers digital speed reference, speed/loadlimit and fuel transfer outputs to its external circuitry as indicatedrespectively by the reference characters 332, 334 and 336.

The coupling of the contact closure output system 316 with the analogspeed control 324 is within the framework of the preferredsoftware/hardware hybrid control system. Another contact closure output338 to the analog speed control 324 provides for a minimum fuel flowinto the turbine combustor system in order to prevent flameout afterignition.

An analog dual fuel control system 337 is operated by the speed control324 to determine the position of the liquid and gas fuel valvesconsidered in connection with FIGS. 9 and 10. A contact closure outputcoupling to the dual fuel control 337 provides for transfer betweenfuels or relative fuel settings for two fuel or single fuel operation asindicated by the reference character 336.

The contact closure output system 316 is also connected to theoperator's panel 120 and to sequence the starting engine 126. Asynchronizer detection circuit 342 has bus line and generator potentialtransformers coupled to its input and the contact closure output system316 signal provides a visual panel indication for manualsynchronization. The detection circuit 342 also supplies signals to theanalog input system 308 for automatic synchronization when suchsynchronization is employed as considered more fully in theaforementioned Reuther and Reed copending patent applications.

Other devices operated by the contact closure outputs include thegenerator field breaker and the generator line breakers 132 and 137. Themotor operator generator exciter field rheostat 171 and 177 and variousdevices in the motor control center 130 and the pressure switch andgauge cabinet 152 also function in response to contact closure outputs.The printer or teletype 310 is operated directly as a specialinput/output channel to the main frame 304. A guide vane control circuit338 is also operated by the speed control 324 to control the position ofthe guide vanes through a guide vane electropneumatic converter 340which actuates the positioning mechanism.

The foregoing is an abbreviated specification of a control systememployed in implementing the preferred embodiment of the presentinvention, suitable for use in gas turbine electric power plant control.A more complete discussion of the preferred control system may be foundin the aforementioned copending application Ser. No. 082,470, SectionB3, pages 51 to 62.

Analog Circuitry

The speed control circuit 324 operates in response to a main speedsignal generated by a main turbine speed sensor 344 associated with a 44tooth magnetic rotor wheel 345 as shown in greater detail in FIG. 16A.The main speed signal is converted into a sinusoidal output waveformhaving a constant width pulse at twice the input frequency. To derive arepresentation of the actual turbine speed, circuit block 348 convertsthe pulse train into a proportional direct voltage output which is thenapplied to error detector circuit block 350 and to analog input system308 (FIG. 9).

A speed reference signal 356 derived from an analog output circuit block362 and a speed regulation feedback signal 358 are also inputs tocircuit block 350. The speed reference signal is determined from adigital command value generated by the computer.

Within circuit block 350 actual speed and speed feedback regulationsignals are added to the speed reference signals to determine a speederror output signal. In the absence of fuel demand limit action, thespeed error, amplified in circuit block 368, is generated on line 369 asthe fuel demand signal, or, contact signal output (CSO), and input tothe fuel control system 337. Monitoring is provided by meter 370.

Low and high limits are generated by setpoint signal generators 374 and378 and imposed on the fuel demand signal in circuit block 372 by clampamplifiers 376 and 382, respectively.

A backup speed limit is imposed on a backup speed limiter 326 in amanner similar to the foregoing. As will be readily appreciated, thereexists a one-to-one functional correspondence between circuit elements344 and 384, 346 and 386, 348 and 388 and other elements shown assimilarly disposed in the schematic diagram depicted in FIG. 16A.

Additional clamp amplifier circuit 390 and speed limiter setpointgenerator 392 cause the fuel demand signal output from circuit block 368to be cut back to a predetermined minimum value if either of two logicconditions is satisfied. The first of such conditions is the operationof the turbine in excess of 108% of rated speed. An auxiliary speedsignal is applied to the input of comparator circuit 396 which generatesan output signal for application to an OR circuit 397 when the speedsignal is too high. As shown, AND circuit 402 responds if LLCSOX exists,to generate a switching signal via the logic inverter 402.

In a like manner a speed derivative signal is processed to detect as asecond logic condition an excess acceleration between 102% and 108% ofrated speed, such that, upon comparison with a predeterminedacceleration limit and determination in circuit block 398 that the speedderivative signal is greater, an output to logic switch 394 is generatedand coupled to the control input of clamping amplifier 390 as alreadydescribed. The fuel demand signal generated at the output of the fueldemand amplifier 368 accordingly is representative of the fuel needed tosatisfy the computer generated speed reference, the fuel needed tosatisfy a computer determined limit action, the low limit fuel demandneeded to prevent flameout during normal speed operations, or to causeturbine speed cutback without flameout when overspeed conditions aredetected by the auxiliary speed limiter circuit 326.

At an input 410 to the dual fuel control system 337 the fuel demandsignal is applied across a computer controlled digital potentiometer 412which is illustrated schematically as an analog potentiometer. The fueldemand signal is also applied to the computer analog input system 308for programmed computer operations. The total fuel demand signal isratioed between the gas fuel control systems 414 and 416 to produce theindividual fuel flows which satisfy gas turbine operation demands.

The gas fuel demand signal is applied to signal range adjusteramplifiers 418 and 420 which provide predetermined operationcharacterization for the gas start valve and the gas throttle valverespectively. A signal range adjuster amplifier 424 operates on theliquid fuel demand signal to produce control on the liquid fuel throttlevalve electropneumatic converter again, in accordance with apredetermined operation characterization. Additional liquid fuel controlis provided by a pressure reference generator 434 and a rate controller436 which serve to operate the liquid fuel bypass valve electropneumaticconverter 270 in accordance with a predetermined pump discharge pressurecharacterization.

The inlet guide vane control 338 considered previously in connectionwith FIG. 9 may include a controller 448 which generates a guide vaneposition control signal as a linear function of the sensed speed signalderived from the error detector block 350 in the main speed channel. Thesubject is considered in greater detail in copending relatedapplications Ser. Nos. 205,261 and 189,633.

Additional functions performed by the analog system indicated in FIG. 9,as well as a more definite discussion of those elements enumerated abovemay be found in copending application Ser. No. 082,470, pages 63 to 74.

Control Panels

The operator's panel considered in connection with FIG. 1 is included aspart of an operator's console through which various process controlfunctions may be initiated or altered. Additionally, process monitoringis provided in the form of various meters and alarms.

Among the general control functions provided are the following:

(a) Breaker pushbutton control,

(b) Automatic synchronization ON/OFF,

(c) Synchronizing mode selection.

Control functions which may be included specific to the gas turbine, areas follows:

(a) Normal start/stop,

(b) Emergency start/stop,

(c) Fuel selection,

(d) Automatic fuel transfer.

Flexible generator control is provided in the form of panel functionswhich permit selection of manual or automatic voltage regulation.

Alarm condition indicators are provided by alarm lights and a horn blow.Typical conditions giving rise to alarm status indications are thosepertaining to system failures during startup. Alarms are provided whichare associated with specific process monitoring devices such asgenerator vibration detectors, combustor basket flame detectors, andblade path and exhaust manifold thermocouples. A facility is providedfor initiating computer determined alarm status responsive controlfunctions.

In the preferred embodiment increased control flexibility is achievedthrough the provisions of one or more remote control panels which,desirably, duplicate the functions of the local operator's panel.

A detailed discussion of the control panels may be found in theaforementioned copending application Ser. No. 082,470, at pages 74through 97 thereof. Included is a listing of local and remote operator'spanel contact closure output assignments, and a description of theentering of control parameter changes into the control system 300.

D. PROGRAM SYSTEM 1. General Configuration

The computer program system is organized to operate the computer system305 so that it interacts with other control system elements and plantdevices to operate the gas turbine plant 100 and other similar plants asrequired to produce electric power with many user advantages. Asschematically illustrated in FIG. 17, the program system comprises asequencing program 600 and a control program 602 which make most of theplant operational determinations for output to the control systeminterfacing and control hardware. An executive program 604 schedules theuse of the computer 304 by the various programs in the software systemin accordance with a predetermined priority structure. The executiveprogram 604 also provides certain other functions considered more fullysubsequently.

Generally, the sequencing program 600 accepts contact closure inputs,analog inputs, and operator console inputs from an operator consoleprogram 606 to provide through contact closure outputs plant startup andother functions including alarm and housekeeping tasks prior to, duringand after startup. As indicated in FIG. 17, the sequencing program 600supervises the control program 602 by specifying the control mode andthe selected load. The control program 602 transmits data to thesequencing program 600 including for example hot blade path temperatureindications during load operation which require plant alarm andshutdown.

An automatic synchronization program 608 is also supervised by thesequencing program 600 to provide for generator voltage regulatorrheostat operation and turbine speed adjustment during automaticsynchronization. The sequencing program 600 processes manualsynchronization operation. It also transmits lamp light determinationsto the operator's console program 606 and alarm determinations to analarm program 610.

The operator's console program 606 is a package of subprograms whichprovides for interfacing the operator's panel 120 with the computer 304.The alarm program 610 proivdes for printout of detected alarms.

During the various modes of plant operation, the control program 602makes intermediate control determinations which result in thedetermination of a turbine speed reference representation and a fueldemand limit representation for application as analog signals to theanalog speed control 324 as previously described. Analog outputs fromthe control program 602, the automatic synchronization program 608 andthe operator's console program 606 are processed by an analog outputpulser program 612 to provide for generation of accurate external analogvoltages corresponding to the internal digital determinations. Analoginputs for the sequencing program 600 and the control program 602 andother programs are determined and stored by an analog scan executiveprogram 614.

A thermocouple check program 616 makes a validity check on thethermocouples not checked by the sequencing program 600 or the controlprogram 602 and generates an alarm for alarm program printout when athermocouple reading indicates an open circuit.

A log program 618 operates in conjunction with a conversion program 620to generate a periodic printout of the values of predeterminedanalog-inputs. Other programs included in the program system areclassified as miscellaneous programs 622.

2. Executive System

In the program system, the individual programs are repeatedly executedunder control of executive program 604, typically with only the programvariables changed. An executive priority system consisting of sublevelstructured dominant and secondary levels defines the order in whichprograms are executed.

Dominant sublevel programs are executed according to real time, i.e. aprogram which is first bid is executed first if two programs are biddingto run simultaneously. Secondary sublevel programs are executedaccording to a preestablished hierarchy.

3. Programmer's Console Package

The programmer's console programs are provided to facilitatecommunication with the P50 computer. Generally, the console packageprovides a means for loading programs into the computer, executingprograms, loading constants or instructions and dumping areas of mainand extended core memory. Core locations can be dumped in binary on tapeor in octal on a keyboard. The programmer's console package operateswithin the priority structure of the executive program 604, and itselements are generally classified as a part of that program.

4. Operator's Console Program

As indicated in FIG. 22, an operator's console program is provided withinterfaces with both the sequencing program 600 and the analog outputprogram 612. Generally, a depressed local operator's pushbutton causesthe interrupt routine to bid a dominant level operator's consoleprogram, which when active determines the requested action. In the eventthat generator breaker closing, line breaker closing or emergencyshut-down have been requested, priority execution of associated programsresults. Other indicated actions occasion the requesting of an associatdsecondary sublevel program, which is then placed into the bidding state.Operator/Executive System communication is provided during all modes ofgas turbine control.

5. Analog Scan Program

Generally, the analog scan program provides an executive function inreading all analog points associated with the power plant 100 and anysimilar plant units. The frequency at which the analog points are readis determined by the needs of the process operation, and in thisinstance, it is set at 30 points per second. The analog scan program canbe executed under hardware or software interrupt lockout.

6. Analog Output Program

As previously considered, the general approach employed for generatinganalog outputs is to employ external holding type operational amplifierswith the amplifier output measured by the computer through the analoginput system 308. The measured value is compared with the desired valueand the difference is employed in determining how long raise or lowercontact closure outputs must be closed to make the holding amplifierintegrate to the desired value. The raise or lower value is computed intenths of a second, and it is determined by an element of the analogoutput program 612, which is run on a secondary level while the actualcontact closure output pulsing is performed by a pulser element of theanalog output program 612, run on a dominant level every tenth of asecond. The secondary level analog output program element is run everysecond for speed reference and load limit and every five seconds for theremaining outputs.

The foregoing brief discussions of system components 2 through 6 areherein included to provide in summary form a general description of thecontrol environment which is more fully described in copendingapplication Ser. No. 082,470 Sections D2 through D6, pages 101 through115.

7. Sequencing Program a. Functional Philosophy

Generally, the sequencing program 600 is represented by a flowchartshown in FIG. 18 and it is run once every second to provide the plantsequencing operations required during turbine startup, to providecertain alarm detections and to provide sequencing for various planttasks during time periods other than the turbine startup time period. Asindicated by block 622, certain information regarding the status of theturbine plane 100 and other controlled plants is required for sequencingprogram execution. The required plant status information which isacquired includes continuous analog data and contact input closuresgenerated by operator panel switches pressure switches, and other plantdevices. The acquired information is stored in a master logic table asindicated by the block 624. Next, in providing ultimately for betterplant startup management and better plant management generally, thestored data is employed in the evaluation of a plurality of blocks ofsequence logic as indicated by block 626.

The results of the evaluation of the sequence logic may requirecommunication with other programs in the program system in which eventthe results are stored for use by those programs. As indicated by block628, the results of the evaluation of the sequence logic may alsorequire certain contact closure outputs. In block 630, a resident tableof turbine data acquired from core memory by the acquisition block 622is saved in the original core memory location while nonresident turbinedata comprising operator panel inputs is allowed to be destroyed.

Block 632 then determines whether any additional turbines need to beprocessed in the current run of the sequencing program 600. If not, thesequencing program 600 is ended. If one or more gas turbines remain forsequencing logic determinations in the current run of the sequencingprogram 600, the program 600 is re-executed for the next turbine and theprocess is repeated until the last turbine has been serviced withsequence logic processing in the current sequencing program execution.

In FIG. 19, there is illustrated a data flow map for the sequencingprogram 600. As shown, there are four turbine data tables for therespectively designated gas turbines A, B, C and D. Each gas turbinedata table comprises a resident portion and a read only portion which isderived from the operator panel program 606. A preprocessor block 634corresponds to the block 622 shown in FIG. 18, and it obtains data fromanalog inputs, contact closure inputs, the resident turbine A table andthe read only turbine A table. The acquired data is stored in a masterlogic table as indicated by block 636 which corresponds to block 624 inFIG. 18. The master logic table is employed in the execution of logicprogram block 638 which corresponds to block 626 in FIG. 18.

After the sequence logic has been evaluated by the program 638 apostprocessor 640 is entered and it corresponds to blocks 628, 630 and632 in FIG. 18. Thus, contact closure outputs are generated and theturbine A resident table is saved. The postprocessor 640 then providesfor a repeat program execution for turbine B table data if a second gasturbine plant is under control. Similarly, repeat executions are made toprovide for entry and restorage of turbine C table data and turbine Dtable data if C and D gas turbine plants are under control. After thelast turbine sequence program execution has been employed, an exit ismade from the postprocessor block 640.

b. Sequencing Program Table Data Tables and Preprocess and PostprocessRoutine

Information on core organization of the turbine read/write and read onlytables, contact closure input and output data tables, the master logictable and turbine alarm data tables may be found in Section D7b., pages117 to 150 of the aforementioned copending application Ser. No. 082,469.Additional information on the contact closure input routines, analoginput routines, contact input and contact closure output routinesemployed in blocks 622 and 628 is included therein.

c. Plant Sequence Functions

Generally, the sequence control subsystem embraces certain logicoperations which provide for an orderly advance of the process throughstartup, run and shutdown operations while providing many operatingadvantages. In providing sequence operations, the sequence controlsubsystem includes the sequencing program which interacts with thecontrol program and with plant devices to provide direction to processevents and simultaneously to provide plant and turbine protection.

In the startup process, a programmed computer master contactor functionand operation selectors are employed to force the sequence of startingand operation to assure that turbine startup will normally take placeover a fixed predetermined time interval. The software master contactorserves to establish and disestablish logic conditions necessary forinitiating the making and breaking of external control circuits forequipment startup and shutdown operations under predetermined plant andequipment conditions.

After ignition programmed sequencing logic causes the control system 300to be placed in Mode 1 operation and the gas turbine speed reference isincreased in a program controlled nonlinear manner to determine the fuelvalve positioning.

When the turbine 104 has been advanced to idle (or top or synchronous)speed, it is ready to be synchronized and the control system 300 istransferred to Mode 2 operation in which either manual or automaticsynchronizing is performed following field breaker closure. When theturbine-generator unit is synchronized and the generator breaker isclosed, the control system 300 is transferred to Mode 3 or Mode 4operation and the speed reference is set at a value of 106% rated speed.Load is ramped to a predetermined level at a predetermined rate underprogrammed computer operation.

Shutdown of the gas turbine is caused if any of three time checks failduring the startup sequence. The first time check measures time frominitiation of the master contactor function to ignition speed. Inaddition, a check is made on the time from detection of flame incombustor baskets to 60% speed. Further, a check is made on the timefrom starting engine trip at 60% rated speed to idle speed.

d. Sequence Logic Charts

In FIGS. 20A and B, there are shown logic diagrams of representativealarm and sequencing functions performed by the sequencing program 600in the block 626 (FIG. 18) each time it is executed. Predetermined logicbuilding blocks are employed in defining the conditions for theperformance of the sequencing program functions. Each block contains asymbol identifying its function and a number of alpha-numeric characterproviding a program block identification. The logic function identifyingsymbol is generally located above the program block identificationcharacter. The following is a list of the logic symbols and the logicfunctions to which they correspond:

A: And

OR: OR

FL: FLIP FLOP

SS: SINGLE SHOT

DB: DEAD BAND

NOT: INVERSION

TDH: TIME DELAY--HOURS

TDS: TIME DELAY--SECONDS.

There is principally shown the logic associated with start/stopoperations and the master contactor or control function to whichreference has already been made. Generally, logic diagram 642 pertainsto the master contactor or control function generated by flip-flop FL7as a function of pushbutton operations and other conditions. Similarly,logic diagram 644 relates to the generation of a shutdown operation inresponse to pushbutton, shutdown alarm and other conditions. Thus,shutdown OR block OR6 resets the master contact function flip-flop FL7when a shutdown is initiated. In the logic diagram 644, alarm shutdownsare initiated by line L86 through block OR4. On shutdown, single shotblock 6 provides for registering predetermined data.

Other sequencing program logic functions set forth in logic diagram formin FIGS. 20A and B include a plurality of generator alarms designed asOR GEN BLK blocks. In addition, block OR1 provides for immediateshutdown on blade path over-temperature through block OR4. Single shotblocks 4, 5 and 14 respectively provide normal start counts, emergencystart counts, and abort counts. A list of miscellaneous alarms is alsoincluded.

Further description of the plant sequence functions, associated sequencelogic charts, macro instructions for sequencing logic and logicsubroutines and macros related thereto may be found in theaforementioned copending application Ser. No. 082,467, Section D.7c.through D.7e. found at pages 151 to 164 thereof.

8. Control Program

The following brief discussion of a control program suitable for use inthe preferred embodiment of the present invention may be considerablyamplified by a reference to the corresponding section of one of theaforementioned copending applications, e.g., Ser. No. 082,470.

As indicated in FIG. 17 the control program 602 interacts with thesequencing program 600 providing control loop determination of theoperation of the gas turbine plant 100 and like plants if provided. Apreferred control arrangement is considered in FIG. 21. Upondetermination by the sequencing program 600 of the control mode in whichthe control program 602 is to be operated and the accomplishment of thesequencing steps previously discussed, control program 602 becomesactive, operating in the control loop arrangement 300A. The hybridinterface depicted provides for software speed reference generation andselection of a single low fuel demand limit in software low select block700 for application to analog hardware speed control 324.

The output fuel demand signal is selected as the lowest of a speed errorfuel demand signal and the computer output fuel demand limit signal aspreviously considered. The actual fuel demand control signal ACTFL isread as an analog input for tracking in various software control pathsas considered more fully subsequently. Surge limit, blade path andexhaust temperature limit and load limit control loops are all providedwith software control functions which respond to external data andgenerate outputs to the software low select block 700 as indicated bythe respective reference characters 702, 704, 706 and 708.

Referring now to FIG. 22, execution of control program 602 proceeds asfollows:

(a) Preprocessing by block 710 of the resident control data tablecontaining various parameters indicating current turbine status and apointer to the sequencing table which contains a control mode indicatorand the selected load and start-up status.

(b) Analog control program data acquisition including blade path,exhaust and compressor inlet temperatures, combustor shell pressure,actual fuel demand signal and actual kilowatt output.

(c) Reliability testing of acquired analog temperature readings toprevent overheating of critical turbine parts.

(d) Execution of turbine control block 712, to be hereinafter outlined.

(e) Block 716 postprocessing including table updates as indicated by thecircular data flow.

The foregoing steps are repeated cyclically for turbines B, C and D ifprovided.

Turbine control block 712 is shown in greater detail in FIG. 23. Asshown, control actions are directed consistent with turbine control modedirectives. If block 718 determines that the turbine is in Mode 0status, initialization is accomplished by the execution of block 720.Actual turbine speed tracking is provided so that a smooth transition ismade in the computer generated speed reference during transfer from Mode0 to Mode 1.

Referring to FIG. 31A a flowchart is shown for those steps of thecontrol program implemented in accordance with the principles of thepresent invention which are executed in Mode 0. Block 900 determineswhether the turbine has reached a speed corresponding to that desirablyattained at light-off. As shown an offset value is computed as thedifference between a scaled analog input value PRES2C (one half thecombustor shell pressure) and a constant 631₈ which is the actualequivalent of one half the number corresponding to one volt, the voltagelevel representing a pressure transducer reading of 0 psig. (Variousscaling techniques are used throughout the control program system. Inthis instance results are carried at half value). Execution of block 902occurs once each second until light-off. Thus, upon the occurrence ofsuch event location OFFSET contains a scaled number representative of anerror attributable to instrumentation drift at shutdown, i.e., driftcompensation is dynamic through initial program execution and becomesfixed at the shutdown value at light-off. In this manner impropertransducer rezeroing is eliminated.

If the control is not in Mode 0, block 722 next determines the surgecontrol function for use in the surge control loop (FIG. 21) in allother modes of operation. To prevent compressor surge under excessivepumping demands, the surge control function determines a maximum fueldemand limit as a function of the compressor inlet temperature and thecombustor shell pressure. A discussion of the surge limit functiondetermination may be found in copending application Ser. No. 082,470beginning at page 186 thereof. Analog inputs representative oftemperature are reliability checked as described in copending relatedapplication Ser. No. 155,905. Combustor shell pressure readings areextremely accurate, having been obtained as a result of the dynamiccalibration and error correcting system and method of the presentinvention.

In Mode 1 control block 726 is executed to provide acceleration controlfrom ignition speed of approximately 1000 RPM to the top speed of 4894RPM. Fuel demand signal tracking is provided and a nonlinear temperaturereference is generated in a manner similar to that employed in surgelimit functional determination, again, as discussed in theaforementioned copending application, Ser. No. 082,470. Temperaturereferences as a function of combustor shell pressure are determined forboth normal and emergency startups.

Repeated executions of the control routine 712 are made during the timeperiod that the gas turbine 104 is placed under sequencing andacceleration operations in Mode 1 control. A speed reference for analogoutput to the speed control 324 is provided in block 728. Such referenceis derived from previously input nonlinear curve representative ofoptimum fixed time acceleration for both normal and emergency startup aspreviously indicated. A linear interpolation routine similar to thatdescribed in connection with the surge limit functional determination isemployed to derive acceleration values at working time points betweenthe time points corresponding to the stored curve points. The speedreference algorithm may be found at page 50 of copending applicationSer. No. 082,470.

The speed reference generation program is shown in greater detail inFIG. 24. Block 730 first determines if the gas turbine 104 has attainedtop or substantially synchronous speed. If this condition is satisfied,the speed reference routine is bypassed and a return is made to theturbine control program execution. If not, block 734 determines whetheran emergency start has been requested. Block 736 and 738 correspondrespectively to emergency and normal startups, and as shown a change inthe speed reference required for the next sampling time interval iscalculated. In block 740 the speed reference step change is added to thepreceding speed reference.

A top speed limit is next placed on the speed reference by block 742 ifblock 744 detects an excessive speed reference value. If not, the speedreference value is stored and a return is made to the execution of thecontrol block 712.

Temperature control is provided as shown in FIG. 25. In the temperaturelimit routine 744 a temperature error is first determined by taking thedifference between the temperature reference previously derived and theactual and preprocessed average blade path temperature. The output ofblock 746 is compared with a predetermined deadband in block 754. If anerror exists outside the deadband, the sign is determined in block 756.If the blade path temperature error is negative, control action isimposed by block 758 with a proportional routine and an integralroutine. Blade path temperature and temperature error variables arestored by block 760 and block 762 sums the results of the proportionaland integral operations of block 758 to generate the blade path outputlimit representation BPSGNL.

If the blade path temperature error is positive, fuel demand signaltracking block 764 is executed so that faster control action may followa change in temperature error from positive to negative, since throughthis device the reset routines do not have to integrate back from somesaturated output value. In particular, the tracking action is such thatthe reset block output never exceeds the fuel demand signal by more thana difference value.

To obtain the tracking action, the desired difference value is added tothe low selected fuel demand signal and the result is differenced fromthe output of a reset of integrator routine and applied to the input ofthe reset routine. The output of the integration operation accordinglytracks the fuel demand signal with a positive bias. Such trackingoperation allows the tracking control loop to enter quickly into fuelcontrol if required by a change in the error quantity controlled by thetracking control loop. The integration routine may be found at page 202of copending application Ser. No. 082,467.

After execution of the block 762, the exhaust temperature control ortracking action is determined in a series of blocks similar to thosejust considered in connection with blade path temperature control andtracking action. Further, a save variable block 769 provides for storingthe exhaust temperature error and the track function output initiated byblock 769. After the exhaust temperature output limit is determined inblock 766 a return is made to the routine 713 in FIG. 23. Next, asoftware low selection is made by block 700 in Mode 1 control programexecution.

Throughout Mode 1 drift offset error corrections are made in deriving acombustor shell pressure value for use in surge limiting. Referring toFIG. 31B, the initial pressure value obtained from an analog input tableis divided by 2, consistent with internal program scaling previouslydiscussed, and stored in PRES2C. If Mode 1 program switch is set on(block 904), the value in PRES2C is replaced by the value PRES2C-OFFSETas indicated at 906. Thus the dynamic calibration and error correctionsteps of the present invention are accomplished.

Summarizing and expressing the foregoing in equation form:

Consistent with the assumption that the pressure transducer iscalibrated over its full range and that the error is in the form of aconstant offset then any transducer reading is given as:

    P2C.sub.transducer =P2C.sub.actual +P2C.sub.error.         (1)

When the unit is on turning gear P2C_(actual) should equal zero. Thus(1) becomes

    P2C.sub.transducer =P2C.sub.error.                         (2)

Therefore, a reading taken at shutdown is a direct measure of the error.After start a corrected pressure reading may be obtained by subtractingP2C_(error) from P2C_(transducer). Thus, ##EQU1##

To briefly examine an example of the operation of the principles of thepresent invention, consider the case where the pressure transducer hadreturned to a 1 lb. setting instead of to 0. This would be read andnoted by the computer and saved in memory. If the transducer slowlydrifted back toward 0 during the shutdown period, the successive changeswould also be noted. Assume that upon restarting P2C reads 0.6 pounds.Then the reading saved would be 0.6 lbs. Thus at startup P_(corrected)=0.6_(psig) -0.6_(psig) =0. All future readings would then be offset bya similar amount.

Once synchronous speed is reached, block 768 in FIG. 23 directs theprogram into Mode 2 control operations. In block 770, the speedreference is set equal to the top speed value plus any speed changeentered into the control loop by manual synchronization operations or byautomatic synchronization program execution. Further, the programoperations are redirected through blocks 726, 728, 744 and 700 as in thecase of Mode 1 control.

After synchronization block 772 or 744 directs control programoperations to a Mode 3 control block 766 or a Mode 4 control block 778according to the operator's panel selection. Mode 3 control, depicted inFIG. 26C provides for determining kilowatt error from the differencebetween a kilowatt reference and actual kilowatts. Proportional andintegral control routines are then applied to the kilowatt error and theresultant controller outputs are summed in order to provide for constantkilowatt control with temperature limit backup. Further, a loading ratelimit is imposed to prevent excessive thermal transients due toexcessive loading rates under automatic or manual incremental loading. Adiscussion of the loading limit subroutine and its operation in Modes 1,2 and 3 may be found at page 194 of copending application Ser. No.082,470.

Initially, in Mode 3 operation, the kilowatt reference is set at aminimum value pending operator selection of a reference value which maynot exceed a value corresponding to the base load exhaust temperaturelimit. Thus, the primary Mode 3 controls are the exhaust temperaturecontrol and the constant kilowatt control, with blade path and surgecontrols providing backup protection.

Mode 4 control (FIG. 26D) differs from Mode 3 control in that noconstant kilowatt function is provided for Mode 4. However, a loadingrate limit is imposed. A temperature reference is determined for use inthe blade path and exhaust temperature limit control block 744.

In both Mode 3 and Mode 4, the block 744 is executed in a mannerconsidered previously in connection with Mode 1. Since no constantkilowatt function is provided for Mode 4, the block 744 provides for atemperature loading operation through exhaust temperature limit action.Under temperature control, the generated power varies with the ambienterror temperature such that more power is generated with lower inlet airtemperature.

Load Mode 3 and load Mode 4 program executions are completed through lowselect block 700 which selects the lowest fuel demand representationassociated with the temperature, surge and load limits to provide thecontrol operation as described. Control program execution through theblock 766 and/or 788, 744 and 700 continues for the duration of Mode 3or Mode 4 load control.

A variety of special control program macros and subroutines are employedin the preferred implementation of the control program 602. A discussionof such may be found in Section D8 of the aforementioned copendingapplication Ser. No. 082,467, pages 198 to 203.

9. Alarm and Thermocouple Check Programs

In the alarm system, alarms are generated in response to sensorsconsidered in connection with FIG. 9. Printout of alarms is made as inthe following example:

    ______________________________________                                                           Turbine                                                    Time    Status     Identification                                                                              Description                                  ______________________________________                                        12:30   ALRM       A             Flame A                                      ______________________________________                                    

The status conditions of the alarms are listed below:

NORM--Normal

ALRM--Alarm

Alarms are determined by the sequencing program 600 and the thermocouplecheck program 616 as previously considered. The alarm program 610 isperiodically executed to print out all points in alarm. Multipleconfusing alarm lightings as encountered with conventional annunciatorpanels are thus avoided.

The thermocouple check program 616 also runs on a periodic basis. Whenit is executed, a check is made of the values stored for allthermocouples not checked by the control program 602 to determine if thethermocouple value is more negative than a predetermined check numberstored in location CHKNO. An excessive negative number is considered anopen circuit and an alarm bit is set for the alarm program 610.

10. Data Logging Program

A formated log is printed in response to execution of the log program618 on a periodic basis selected by the plant operator within the rangeof 15 minutes to two hours. The printed readings are instantaneousvalues obtained from the last analog scan cycle. The plant operation mayselect any 20 analog points per turbine under control.

Generally, the analog conversion program 602 provides for convertingentered analog values into the engineering value represented by theinput and vice versa. Generally, four types of conversion are provided,i.e., flow straight-line, thermocouple, and segmented straight-line.

11. Miscellaneous Programs

The miscellaneous programs 622 include a programmer's console functionprogram, a dead switch computer program, a power failure and restartprogram, and a horn and alarm lamp program. Additional programmer'sconsole functions designated herein as being implemented bymiscellaneous programs rather than the executive program include a CCIprint status program, an analog engineering units print program, acontact output operate program, a test dead computer system program anda time program.

The alarm and thermocouple check programs, data logging program, andmiscellaneous programs are more fully discussed in the aforementionedcopending application Ser. No. 082,470, Section D9 to Section D11, pages204 to 210.

We claim:
 1. A control for a gas turbine electric power plant having agas turbine with compressor, combustion and turbine elements, agenerator drivably coupled to said turbine for generating electricpower, said control comprising fuel supply means for supplying fuel tosaid gas turbine combustion element, control means for controlling theoperation of said plant, means responsively coupled to said controlmeans for operating said fuel supply means to supply fuel to saidcombustion elements in controlled quantities, and pressure detectionmeans positioned in said plant to sense combustion shell pressure insaid combustion element and coupled to apply a signal representative ofcombustion shell pressure to said control means means for storing acalibration value for said pressure signal based on the relative valuesof the actual pressure signal and an expected pressure signal valueduring the last turbine shutdown, said calibration value being utilizedby said control means to compensate the actual pressure signal providedby said detection means during turbine operation.
 2. A gas turbinecontrol as set forth in claim 1 wherein said storing means stores acalibration value for said pressure detection means equal to thedifference between the actual and expected signal values substantiallyat the time of lightoff during turbine startup.
 3. A gas turbine controlas set forth in claim 1 wherein said control means includes digitalcomputer means which in turn includes said storing means and includesadditional means for predetermined monitoring and control functions forsaid control means.